WO2021118586A1 - Procédé et système de détermination de variations dans un canal fluidique - Google Patents

Procédé et système de détermination de variations dans un canal fluidique Download PDF

Info

Publication number
WO2021118586A1
WO2021118586A1 PCT/US2019/066164 US2019066164W WO2021118586A1 WO 2021118586 A1 WO2021118586 A1 WO 2021118586A1 US 2019066164 W US2019066164 W US 2019066164W WO 2021118586 A1 WO2021118586 A1 WO 2021118586A1
Authority
WO
WIPO (PCT)
Prior art keywords
fluidic channel
dart
variation
pressure pulse
controller
Prior art date
Application number
PCT/US2019/066164
Other languages
English (en)
Inventor
Oluwatosin OGUNDARE
Claudio Olmi
David B. Bennett
Terry Don BICKLEY
Daniel Joshua Stark
Jeremy Coss NICHOLSON
Original Assignee
Halliburton Energy Services, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to CA3145922A priority Critical patent/CA3145922C/fr
Priority to MX2022005471A priority patent/MX2022005471A/es
Priority to GB2206614.6A priority patent/GB2604489B/en
Priority to AU2019477996A priority patent/AU2019477996A1/en
Priority to BR112022007048A priority patent/BR112022007048A2/pt
Publication of WO2021118586A1 publication Critical patent/WO2021118586A1/fr
Priority to NO20220540A priority patent/NO20220540A1/no

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/04—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
    • E21B23/0413—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion using means for blocking fluid flow, e.g. drop balls or darts
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/08—Measuring diameters or related dimensions at the borehole
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/08—Introducing or running tools by fluid pressure, e.g. through-the-flow-line tool systems
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/117—Detecting leaks, e.g. from tubing, by pressure testing
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01M—TESTING STATIC OR DYNAMIC BALANCE OF MACHINES OR STRUCTURES; TESTING OF STRUCTURES OR APPARATUS, NOT OTHERWISE PROVIDED FOR
    • G01M3/00—Investigating fluid-tightness of structures
    • G01M3/005—Investigating fluid-tightness of structures using pigs or moles
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01M—TESTING STATIC OR DYNAMIC BALANCE OF MACHINES OR STRUCTURES; TESTING OF STRUCTURES OR APPARATUS, NOT OTHERWISE PROVIDED FOR
    • G01M3/00—Investigating fluid-tightness of structures
    • G01M3/02—Investigating fluid-tightness of structures by using fluid or vacuum
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01M—TESTING STATIC OR DYNAMIC BALANCE OF MACHINES OR STRUCTURES; TESTING OF STRUCTURES OR APPARATUS, NOT OTHERWISE PROVIDED FOR
    • G01M3/00—Investigating fluid-tightness of structures
    • G01M3/02—Investigating fluid-tightness of structures by using fluid or vacuum
    • G01M3/04—Investigating fluid-tightness of structures by using fluid or vacuum by detecting the presence of fluid at the leakage point
    • G01M3/042—Investigating fluid-tightness of structures by using fluid or vacuum by detecting the presence of fluid at the leakage point by using materials which expand, contract, disintegrate, or decompose in contact with a fluid
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01M—TESTING STATIC OR DYNAMIC BALANCE OF MACHINES OR STRUCTURES; TESTING OF STRUCTURES OR APPARATUS, NOT OTHERWISE PROVIDED FOR
    • G01M3/00—Investigating fluid-tightness of structures
    • G01M3/02—Investigating fluid-tightness of structures by using fluid or vacuum
    • G01M3/26—Investigating fluid-tightness of structures by using fluid or vacuum by measuring rate of loss or gain of fluid, e.g. by pressure-responsive devices, by flow detectors
    • G01M3/28—Investigating fluid-tightness of structures by using fluid or vacuum by measuring rate of loss or gain of fluid, e.g. by pressure-responsive devices, by flow detectors for pipes, cables or tubes; for pipe joints or seals; for valves ; for welds
    • G01M3/2807—Investigating fluid-tightness of structures by using fluid or vacuum by measuring rate of loss or gain of fluid, e.g. by pressure-responsive devices, by flow detectors for pipes, cables or tubes; for pipe joints or seals; for valves ; for welds for pipes
    • G01M3/2815—Investigating fluid-tightness of structures by using fluid or vacuum by measuring rate of loss or gain of fluid, e.g. by pressure-responsive devices, by flow detectors for pipes, cables or tubes; for pipe joints or seals; for valves ; for welds for pipes using pressure measurements

Definitions

  • the present disclosure relates generally to a system and method to determine variations in a fluidic channel.
  • the present disclosure relates to a system and method to determine variations in a fluidic channel utilizing a dart.
  • Wellbores are drilled into the earth for a variety of purposes including tapping into hydrocarbon bearing formations to extract the hydrocarbons for use as fuel, lubricants, chemical production, and other purposes. These hydrocarbons are often transmitted to processing plants via pipelines. Fluidic channels such as pipelines and wellbores need to be inspected to determine variations such as junctions, nipples, leaks, blockages by deposits, or structural erosion or damage.
  • FIG. 1A is a schematic diagram of an exemplary environment for a system for determining a variation of a fluidic channel according to the present disclosure
  • FIG. IB is a schematic diagram of another exemplary environment for a system for determining a variation of a fluidic channel according to the present disclosure
  • FIG. 1C is a schematic diagram of a controller which may be employed according to the present disclosure.
  • FIG. 2 is a schematic diagram of a dart used in the system of FIGS. 1A and IB;
  • FIG. 3 is a flow chart of a method to determine variations in a fluidic channel according to the present disclosure
  • FIGS. 4A-4E are schematic diagrams of a dart translating within a fluidic channel to determine variations in the fluidic channel according to the present disclosure
  • FIG. 5 is an exemplary diagram of a pressure profile recorded in the fluidic channel after induction of pressure pulses by the dart.
  • Variations can include, for example, a change in the diameter of the fluidic channel, a joint, a junction, a perforation, a nipple, a leak, an indentation, and/or deposits in the fluidic channel.
  • the system includes a dart disposed in a fluidic channel, such as a wellbore, a conduit, and/or a pipeline.
  • the dart includes one or more flanges extending from the body of the dart.
  • the flanges have a diameter equal to or greater than a diameter of the fluidic channel, such that when the dart translates within the fluidic channel, the flanges are in contact with the walls of the fluidic channel and, in some examples, are flexed.
  • the dart can include a pig.
  • the dart can include an oversized pig where the flanges are larger than the fluidic channel.
  • the flanges of the dart flex due to the change in the walls of the fluidic channel.
  • the flanges may be flexed or bent against the walls when the dart translates along the fluidic channel.
  • the flanges may straighten and then flex again when coming back in contact with the standard shape of the walls.
  • the flange may be straight or in a natural state, and when the flange abuts against a variation in the walls, such as a nipple or a deposit, the flange may flex and then return to the initial configuration after passing the variation.
  • the changes, such as flexing and/or straightening, in the flange create a pressure pulse within the fluid of the fluidic channel.
  • the pressure pulse traverses through the fluid of the fluidic channel, and is measured by a pressure sensor.
  • one or more pressure sensors may be disposed behind the dart.
  • one or more pressure sensors may be disposed in front of the dart in the direction that the dart is traveling.
  • the pressure sensor(s) is communicatively coupled with a controller.
  • the controller receives data from the pressure sensor(s) and determines the location of the variation. For example, the controller can determine the location of the variation based on the timing of the pressure pulse. In some examples, the controller can determine the type of variation, for example based on the shape and/or amplitude of the pressure pulse.
  • the system can be employed in an exemplary wellbore environment 10 shown, for example, in FIG. 1A.
  • the environment 10 includes a drilling rig 12 extending over and around a fluidic channel 50, such as a wellbore 14 in FIG. 1A.
  • the wellbore 14 is within an earth formation 22 and has a casing 20 lining the wellbore 14, the casing 20 is held into place by cement 16.
  • a dart 100 can be disposed within the wellbore 14 and moved up and/or down the wellbore 14 via a conduit 18 to a desired location.
  • the dart 100 can be fluid propelled.
  • the dart 100 can include a motor and propeller system such that the dart 100 can translate within the wellbore 14.
  • the dart 100 can include a downhole tool to carry out logging and/or other operations.
  • the conduit 18 can be, for example, tubing-conveyed, wireline, slickline, work string, joint tubing, jointed pipe, pipeline, coiled tubing, and/or any other suitable means for conveying darts 100 into a fluidic channel 50 such as a wellbore 14.
  • the conduit 18 can include electrical and/or fiber optic cabling for carrying out communications.
  • the conduit 18 can be sufficiently strong and flexible to tether the dart 100 through the wellbore 14, while also permitting communication through the conduit 18 to one or more of the processors, which can include local and/or remote processors.
  • power can be supplied via the conduit 18 to meet power requirements of the dart 100.
  • a data acquisition system 195 includes one or more sensors 190 communicatively coupled with a controller 200 which can receive and/or process the data received from the sensors 190. While FIG. 1A illustrates one sensor 190, in other examples, more than one sensor 190 may be utilized. In at least one example, as illustrated in FIG. 1A, one or more sensors 190 can be disposed within the fluidic channel 50 at predetermined locations. The sensor 190 is positioned to measure pressure in the fluidic channel 50. Additionally, the sensor 190 may measure parameters related to the wellbore 14 and/or fluid in the wellbore 14, such as flow rate, temperature, and/or composition.
  • additional sensors 190 may measure additional parameters related to the wellbore 14 and/or the fluid in the wellbore 14 such as flow rate, temperature, and/or composition.
  • sensor 190 can be disposed within the wellbore 14, for example coupled with or disposed in the casing 20, as illustrated in FIG. 1A.
  • the system may also be employed in an exemplary system 150 shown, for example, in FIG. IB.
  • FIG. IB illustrates a dart 100 deployed in a fluidic channel 50 such as a pipeline 160.
  • the fluidic channel 50 can be, for example, a wellbore as illustrated in FIG. 1A, a conduit, or any channel through which fluid flows.
  • the fluidic channel 50 has a first end 1060 and a second end 1062. Each of the first end 1060 and the second end 1062 are open such that the first and second ends 1060, 1062 are accessible by an operator and fluid can flow through the open ends. In other examples, the second end 1062 of the fluidic channel 50 is closed such that fluid cannot flow through the second end 1062. In at least one example, the first and second ends 1060, 1062 can be located along any point of the fluidic channel 50. For example, the first end 1060 may be located in the middle of the fluidic channel 50. The first end 1060 is any entry point to gain access to the fluidic channel 50. As illustrated in FIG. IB, the fluidic channel 50 has a vertical section 1064 and a horizontal section 1066. In other examples, the fluidic channel 50 can extend only in one direction or multiple directions along any axis.
  • the fluidic channel 50 has walls 162 which form an annulus 166 through which fluid 164 can be contained in and flow.
  • the fluid 164 can be one fluid or more than one fluid.
  • the fluid 164 can include, for example, water and/or oil.
  • the fluid 164 can also substantially fill the entire fluidic channel 50. In other examples, the fluid 164 can partially fill the fluidic channel 50.
  • the walls 162 of the fluidic channel 50 can form a cross-sectional shape such as substantially circular, ovoid, rectangular, or any other suitable shape.
  • the walls 162 of the fluidic channel 50 can be made of any combination of plastics or metals, suitable to withstand fluid flow without corrosion and with minimal deformation.
  • the fluidic channel 50 can also include one or more ports 1061.
  • the ports 1061 extend through the walls 162 of the fluidic channel 50. As such, the ports 1061 permit communication across the walls 162 from external the fluidic channel 50 to the annulus 166 within the fluidic channel 50.
  • the system 100 includes a data acquisition system 195, similar to the data acquisition system 195 of FIG. 1A, which receives and processes data such that the data can be used and interpreted by a user.
  • the data acquisition system 195 can be proximate to the first end 1060 of the fluidic channel 50.
  • the data acquisition system 195 can include one or more sensors 190 communicatively coupled with a controller 200 which can receive and/or process the data received from the sensors 190.
  • the sensors 190 can be coupled with the controller 200 by a transmission system 154.
  • the transmission system 154 can be wireline, optical fiber, wirelessly such as through the cloud or Bluetooth, or any other suitable method to transmit data. In some examples, as illustrated in FIG.
  • the controller 200 can be located in a data center 110.
  • the data center 110 may be above ground, under water, underground, or located at any point to collect data.
  • the data center 110 may be an underwater vehicle such as a submarine.
  • the data center 110 may be located on a platform, as illustrated in FIG. IB.
  • variations 51 in the fluidic channel 50 may form.
  • the variations 51 can be a change of shape and/or cross-sectional area, for example, of the fluidic channel 50 any amount and in any shape and form.
  • the variations 51 may extend into the annulus 166 of the fluidic channel 50.
  • Variations 51 can be caused, for example, by deformation of the walls 162 of the fluidic channel 50, deposits formed along the walls 162 of the fluidic channel 50, a change in the diameter D1 of the fluidic channel 50, joints, junctions, perforations, leaks, indentations, and/or nipples.
  • Deposits can be, for example, wax deposits, clay deposits, or any other possible deposits that can adhere to the walls 162 of the fluidic channel 50 such that the fluid flow is at least partly impeded.
  • FIG. 1A illustrates an example of a nipple
  • FIG. IB illustrates an example of a junction and an indentation in the fluidic channel 50.
  • the fluidic channel 50 may not have any variations 51.
  • the cross-sectional shape of the fluidic channel 50 can be substantially circular or any other originally desired shape as discussed above.
  • the fluidic channel 50 may have variations 51.
  • the change in shape of the fluidic channel 50 by the variation 51 can cause the cross-sectional shape of the fluidic channel 50 to be substantially ovoid, rectangular, diamond, triangular, irregular, or any other possible shape other than the original shape of the fluidic channel 50.
  • the illustrated portion of the fluidic channel 50 has one portion with variations 51.
  • the fluidic channel 50 can be more than one portion with variations 51.
  • the fluidic channel 50 may not have any portions with variations 51.
  • FIG. 1C is a block diagram of an exemplary controller 200.
  • Controller 200 is configured to perform processing of data and communicate with the sensors 190, for example as illustrated in FIGS. 1A and IB. In operation, controller 200 communicates with one or more of the components discussed herein and may also be configured to communication with remote devices/systems.
  • controller 200 includes hardware and software components such as network interfaces 210, at least one processor 220, sensors 260 and a memory 240 interconnected by a system bus 250.
  • Network interface(s) 210 can include mechanical, electrical, and signaling circuitry for communicating data over communication links, which may include wired or wireless communication links.
  • Network interfaces 210 are configured to transmit and/or receive data using a variety of different communication protocols, as will be understood by those skilled in the art.
  • Processor 220 represents a digital signal processor (e.g., a microprocessor, a microcontroller, or a fixed-logic processor, etc.) configured to execute instructions or logic to perform tasks in a wellbore environment.
  • Processor 220 may include a general purpose processor, special-purpose processor (where software instructions are incorporated into the processor), a state machine, application specific integrated circuit (ASIC), a programmable gate array (PGA) including a field PGA, an individual component, a distributed group of processors, and the like.
  • Processor 220 typically operates in conjunction with shared or dedicated hardware, including but not limited to, hardware capable of executing software and hardware.
  • processor 220 may include elements or logic adapted to execute software programs and manipulate data structures 245, which may reside in memory 240.
  • Sensors 260 which may include sensors 190 as disclosed herein, typically operate in conjunction with processor 220 to perform measurements, and can include special-purpose processors, detectors, transmitters, receivers, and the like. In this fashion, sensors 260 may include hardware/software for generating, transmitting, receiving, detection, logging, and/or sampling magnetic fields, seismic activity, and/or acoustic waves, or other parameters.
  • Memory 240 comprises a plurality of storage locations that are addressable by processor 220 for storing software programs and data structures 245 associated with the embodiments described herein.
  • An operating system 242 portions of which may be typically resident in memory 240 and executed by processor 220, functionally organizes the device by, inter alia, invoking operations in support of software processes and/or services 244 executing on controller 200. These software processes and/or services 244 may perform processing of data and communication with controller 200, as described herein. Note that while process/service 244 is shown in centralized memory 240, some examples provide for these processes/services to be operated in a distributed computing network.
  • processors and memory types including various computer-readable media, may be used to store and execute program instructions pertaining to the fluidic channel evaluation techniques described herein.
  • program modules may be encoded in one or more tangible computer readable storage media for execution, such as with fixed logic or programmable logic (e.g., software/computer instructions executed by a processor, and any processor may be a programmable processor, programmable digital logic such as field programmable gate arrays or an ASIC that comprises fixed digital logic.
  • any process logic may be embodied in processor 220 or computer readable medium encoded with instructions for execution by processor 220 that, when executed by the processor, are operable to cause the processor to perform the functions described herein.
  • the controller 200 can apply machine learning, such as a neural network or sequential logistic regression and the like, to determine relationships between the signals from the pressure pulses received by the sensors 190.
  • a deep neural network may be trained in advance to capture the complex relationship between an acoustic wave and the location of the variation.
  • the deep neural network may be trained to capture the complex relationship between the acoustic wave and the type of variation. This neural network can then be deployed in the determination of the variation. As such, the determination of variations 51 within a fluidic channel 50 can be more accurate.
  • a dart 100 is disposed in and passed through the fluidic channel 50.
  • FIG. 2 illustrates an example of a dart 100 according to the present disclosure.
  • the dart 100 can include, for example a pig or a plug which is passed through the fluidic channel 50.
  • the dart 100 has a main body 102 and one or more flanges 104 extending from the main body 102. As illustrated in FIG. 2, the main body 102 and the flanges 104 are both substantially cylindrical. In some examples, the main body 102 and/or the flanges 104 may be a rectangular prism, irregularly shaped, ovoid, and/or any other desired shape such that the dart 100 can pass through the fluidic channel 50.
  • the dart 50 is disposed in the annulus 14, 166 of the fluidic channel 50 such that the flanges 104 of the dart 100 abut the walls 20, 162 of the fluidic channel 50.
  • the flanges 104 have a diameter D2 greater than or equal to a diameter D1 of the fluidic channel 50. Accordingly, the flanges 104 maintain the abutment against the walls 20, 162 of the fluidic channel 50 such that the flanges 104 flex when passing any variation 51 in the fluidic channel 50. As the flanges 104 flex, the flanges 104 create a pressure pulse.
  • the flanges 104 may flex and may have a desired amount of flex based on the elasticity of the material of the flanges 104. In some examples, the flanges 104 may flex based on the size and/or shape differential in relation to the walls 20, 162 of the fluidic channel 50 and/or the variations 51. The material selection, shape, and/or size of the flange 104 are sufficient for structural integrity while elastically deforming to an extent to result in an appreciable movement to generate a pressure pulse. As illustrated in FIG. 2, the flanges 104 have a thickness which is sloped. In other examples, the flanges 104 may have a uniform thickness.
  • the flanges 104 may be a thin flange 104 such as a fin.
  • the flanges 104 can have any suitable shape so long as the flanges 104 abut the walls 20, 162 of the fluidic channel 50 and flex when passing by a variation 51 in the fluidic channel 50.
  • one or more sensors 190 of a data acquisition system 195 receive the pressure pulse signals created by the dart 100.
  • the sensors 190 can be disposed in front of and/or behind the dart 100 in relation to the direction of translation of the dart 100 in the fluidic channel 50.
  • the sensor 190 can include a pressure transducer.
  • the sensors 190 can be any suitable sensor that measures pressure or stress of the fluid, for example a string gauge or an optical fiber transducer.
  • the sensors 190 can be disposed within the annulus 14, 166 of the fluidic channel 50.
  • the sensors 190 as illustrated in FIG. IB, can be mounted to and/or inserted through a port 1061 of the fluidic channel 50.
  • the port 1061 may be pre-existing, so the fluidic channel 50 does not need to be modified or disrupted to position the sensors 190.
  • the sensors 190 can be disposed external to the fluidic channel 50.
  • the signals received by the sensors 190 are passed to a controller 200 to be interpreted to map out and quantify any variations 51 in the fluidic channel 50.
  • the controller 200 can be located at the surface, within a vehicle such as a submarine, or any other suitable location such that the data can be interpreted by an operator.
  • the controller 200 can determine the location of the variations 51 based on the measured pressure pulse. In some examples, the controller 200 can determine the location of the variation 51 based on the time that the pressure pulse is sensed by the sensor.
  • the controller 200 can determine the type of the variation 51, for example whether the variation 51 includes a change in the diameter of the fluidic channel, a joint, a junction, a perforation, a nipple, a leak, an indentation, and/or deposits in the fluidic channel. In some examples, the controller 200 can determine the type of the variation 51 based on the shape and/or amplitude of the pressure pulse. In some examples, the controller 200 can determine the type of the variation 51 as well as the location of the variation 51.
  • FIG. 3 a flowchart is presented in accordance with an example embodiment.
  • the method 300 is provided by way of example, as there are a variety of ways to carry out the method.
  • the method 300 described below can be carried out using the configurations illustrated in FIG. 1A-2 and 4-6, for example, and various elements of these figures are referenced in explaining example method 300.
  • Each block shown in FIG. 3 represents one or more processes, methods or subroutines, carried out in the example method 300.
  • the illustrated order of blocks is illustrative only and the order of the blocks can change according to the present disclosure. Additional blocks may be added or fewer blocks may be utilized, without departing from this disclosure.
  • the example method 300 can begin at block 302.
  • a dart translates within a fluidic channel.
  • the dart includes a flange which extends from a main body.
  • the flange has a diameter greater than or equal to a diameter of the fluidic channel such that when the dart translates within the fluidic channel and passes a location of a variation in the fluidic channel, the flange creates a pressure pulse.
  • the flange creates a pressure pulse by flexing when passing by a variation.
  • FIGS. 4A-4E illustrate a dart 100 translating within a fluidic channel 50.
  • the fluidic channel 50 includes one or more variations 51.
  • the variations 51 can include at least one of the following: a change in the diameter D1 of the fluidic channel 50, a joint, a junction, a perforation, a nipple, a leak, an indentation, deposits in the fluidic channel 50, and/or any change in the fluidic channel 50.
  • the fluidic channel 50 as illustrated in FIGS. 4A-4E include an initial variation 55, a junction 52, and a joint 54.
  • a pressure sensor measures a pressure pulse created by the dart when the dart passes by a location of a variation in the fluidic channel. For example as illustrated in FIGS. 4B, 4D, and 4E, as the dart 100 passes by each of the variations 51, the dart 100 creates a pressure pulse 120 which is sensed by one or more sensors 190.
  • an initial variation 55 can be located at a trigger point such that the dart 100 creates an initial pressure pulse 122 when passing by the trigger point.
  • a sensor 190 is located at the trigger point. In other examples, the sensor 190 can be located at any other location such that the sensor 190 can measure the pressure within the fluidic channel 50.
  • the variation 51 includes a junction 52. As the dart 100 passes by the opening formed by the junction 52, the flange of the dart 100 flexes which creates the pressure pulse 120 sensed by the sensor 190. As illustrated in FIG. 4E, the variation 51 includes a joint 54. Similarly, as the dart 100 passes by the change in the walls of the fluidic channel 50 formed by the junction 52, the flange of the dart 100 flexes which creates the pressure pulse 120 sensed by the sensor 190.
  • a controller determines the location of the variation based on the measured pressure pulse.
  • the controller 200 can be communicatively coupled with the sensor 190.
  • FIG. 5 illustrates a diagram 600 of a pressure profile recorded in the fluidic channel after induction of pressure pulses by the dart.
  • Pressure 602 can correspond with the initial pressure pulse created by the dart when passing by the trigger point.
  • Pressures 604 and 606 can correspond with pressure pulses created by the dart when passing by additional variations.
  • the controller can determine the location of the variation based on the time that the pressure pulse is sensed by the sensor. For example, in FIG. 5, time T2 from the initial pressure 602 corresponding to pressure 606 is greater than time T1 from the initial pressure 602 corresponding to pressure 604. Accordingly, the controller can determine the location of the variation corresponding to pressure 606 is further than the variation corresponding to pressure 604. Additionally, in some examples, the length of time from the initial pressure 602 can be utilized to determine the distance of the variation from the trigger point. For example, the controller can calculate the rate that the pressure pulse would travel based on the properties of the fluid in the fluidic channel. In at least one example, the controller can determine the type of the variation based on the shape and/or amplitude of the pressure pulse.
  • a system comprising: a dart disposed in a fluidic channel, the dart having a main body and a flange extending from the main body, the flange having a diameter greater than or equal to a diameter of the fluidic channel, wherein when the dart translates within the fluidic channel and passes a location of a variation in the fluidic channel, the flange creates a pressure pulse; a pressure sensor to measure the pressure pulse within the fluidic channel created by the dart; and a controller communicatively coupled with the sensor, the controller determining the location of the variation based on the measured pressure pulse.
  • Statement 2 A system is disclosed according to Statement 1, wherein the fluidic channel includes at least one of the following: a pipeline, a conduit, and/or a wellbore.
  • Statement 3 A system is disclosed according to Statements 1 or 2, wherein the dart is configured to flex in response to passing the variation in the fluidic channel, and the controller is configured to detect a pressure pulse generated in response to the flexing of the flange.
  • Statement 4 A system is disclosed according to any of preceding Statements 1-3, wherein the controller determines the location of the variation based on the time that the pressure pulse is sensed by the sensor.
  • Statement 5 A system is disclosed according to any of preceding Statements 1-4, wherein the controller determines a type of the variation.
  • Statement 6 A system is disclosed according to Statement 5, wherein the type of the variation includes at least one of the following: a change in the diameter of the fluidic channel, a joint, a junction, a perforation, a nipple, a leak, an indentation, and/or deposits in the fluidic channel.
  • Statement 7 A system is disclosed according to Statement 5, wherein the controller determines the type of the variation based on the shape and/or amplitude of the pressure pulse.
  • Statement 8 A system is disclosed according to any of preceding Statements 1-7, wherein the fluidic channel has walls forming an annulus, wherein the dart is disposed in the annulus of the fluidic channel, and wherein the flange abuts the walls of the fluidic channel.
  • Statement 9 A system is disclosed according to any of preceding Statements 1-8, wherein the dart includes a pig.
  • Statement 10 A system is disclosed according to any of preceding Statements 1-9, wherein the fluidic channel includes an initial variation at a trigger point such that the dart creates an initial pressure pulse when passing by the trigger point, wherein the controller determines the location of the variation by comparing the timing of the pressure pulse for the variation with the timing of the initial pressure pulse for the trigger point.
  • a data acquisition system comprising: a pressure sensor to measure a pressure pulse within a fluidic channel created by a dart; and a controller communicatively coupled with the sensor, the controller determining a location of a variation based on the measured pressure pulse.
  • Statement 12 A data acquisition system is disclosed according to Statement 11, wherein the dart includes a main body and a flange extending from the main body, the flange having a diameter greater than or equal to a diameter of the fluidic channel, wherein the dart is configured to flex in response to passing the variation in the fluidic channel, and the controller is configured to detect a pressure pulse generated in response to the flexing of the flange.
  • Statement 13 A data acquisition system is disclosed according to Statements 11 or 12, wherein the controller determines the location of the variation based on the time that the pressure pulse is sensed by the sensor.
  • Statement 14 A data acquisition system is disclosed according to any of preceding Statements 11-13, wherein the controller determines a type of the variation.
  • Statement 15 A data acquisition system is disclosed according to Statement 14, wherein the type of the variation includes at least one of the following: a change in the diameter of the fluidic channel, a joint, a junction, a perforation, a nipple, a leak, an indentation, and/or deposits in the fluidic channel.
  • Statement 16 A data acquisition system is disclosed according to Statement 14, wherein the controller determines the type of the variation based on the shape and/or amplitude of the pressure pulse.
  • Statement 17 A data acquisition system is disclosed according to any of preceding Statements 11-16, wherein the fluidic channel includes an initial variation at a trigger point such that the dart creates an initial pressure pulse when passing by the trigger point, wherein the controller determines the location of the variation by comparing the timing of the pressure pulse for the variation with the timing of the initial pressure pulse for the trigger point.
  • Statement 18 A method is disclosed comprising: translating a dart within a fluidic channel; measuring, by a pressure sensor, a pressure pulse created by the dart when the dart passes by a location of a variation in the fluidic channel; and determining, by a controller, the location of the variation based on the measured pressure pulse.
  • Statement 19 A method is disclosed according to Statement 18, wherein the controller determines the location of the variation based on the time that the pressure pulse is sensed by the sensor.
  • Statement 20 A method is disclosed according to Statements 18 or 19, further comprising: determining, by the controller, a type of the variation based on the shape and/or amplitude of the pressure pulse.

Landscapes

  • Physics & Mathematics (AREA)
  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • General Physics & Mathematics (AREA)
  • Geophysics (AREA)
  • Measuring Fluid Pressure (AREA)
  • Measuring Volume Flow (AREA)
  • Mechanical Engineering (AREA)

Abstract

Système comprenant une fléchette, un capteur de pression et un dispositif de commande couplé en communication avec le capteur. La fléchette est agencée dans un canal fluidique. La fléchette a un corps principal et une bride s'étendant à partir du corps principal et a un diamètre supérieur ou égal à un diamètre du canal fluidique. Lorsque la fléchette se déplace à l'intérieur du canal fluidique et fait passer un emplacement d'une variation dans le canal fluidique, la bride crée une impulsion de pression. Le capteur de pression mesure l'impulsion de pression à l'intérieur du canal fluidique créé par la fléchette. Le dispositif de commande détermine l'emplacement de la variation sur la base de l'impulsion de pression mesurée.
PCT/US2019/066164 2019-12-13 2019-12-13 Procédé et système de détermination de variations dans un canal fluidique WO2021118586A1 (fr)

Priority Applications (6)

Application Number Priority Date Filing Date Title
CA3145922A CA3145922C (fr) 2019-12-13 2019-12-13 Procede et systeme de determination de variations dans un canal fluidique
MX2022005471A MX2022005471A (es) 2019-12-13 2019-12-13 Metodo y sistema para determinar variaciones en un canal de fluido.
GB2206614.6A GB2604489B (en) 2019-12-13 2019-12-13 Method and system to determine variations in a fluidic channel
AU2019477996A AU2019477996A1 (en) 2019-12-13 2019-12-13 Method and system to determine variations in a fluidic channel
BR112022007048A BR112022007048A2 (pt) 2019-12-13 2019-12-13 Sistema, sistema de aquisição de dados e método
NO20220540A NO20220540A1 (en) 2019-12-13 2022-05-06 Method and system to determine variations in a fluidic channel

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US16/713,118 2019-12-13
US16/713,118 US11519807B2 (en) 2019-12-13 2019-12-13 Method and system to determine variations in a fluidic channel

Publications (1)

Publication Number Publication Date
WO2021118586A1 true WO2021118586A1 (fr) 2021-06-17

Family

ID=76317755

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2019/066164 WO2021118586A1 (fr) 2019-12-13 2019-12-13 Procédé et système de détermination de variations dans un canal fluidique

Country Status (8)

Country Link
US (1) US11519807B2 (fr)
AU (1) AU2019477996A1 (fr)
BR (1) BR112022007048A2 (fr)
CA (1) CA3145922C (fr)
GB (1) GB2604489B (fr)
MX (1) MX2022005471A (fr)
NO (1) NO20220540A1 (fr)
WO (1) WO2021118586A1 (fr)

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20030185100A1 (en) * 2002-03-29 2003-10-02 Schlumberger Technology Corporation Assessing a solids deposit in an oilfield pipe
US20140331745A1 (en) * 2010-09-30 2014-11-13 Siemens Aktiengesellschaft Pipeline leak location using ultrasonic flowmeters
US20160199888A1 (en) * 2013-12-04 2016-07-14 Halliburton Energy Services, Inc. Deposit build-up monitoring, identification and removal optimization for conduits
US20170254165A1 (en) * 2010-10-06 2017-09-07 Packers Plus Energy Services Inc. Actuation dart for wellbore operations, wellbore treatment apparatus and method
WO2019199344A1 (fr) * 2018-04-12 2019-10-17 Halliburton Energy Services, Inc. Procédé et système de détermination non intrusive de variation transversale pour un canal fluidique

Family Cites Families (53)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2698363A (en) * 1953-11-12 1954-12-28 Shell Dev Pipe line indicator for scrapers
US2820959A (en) * 1956-03-05 1958-01-21 Standard Oil Co Pipeline scraper-locator transmitter
US3539915A (en) * 1967-11-03 1970-11-10 American Mach & Foundry Pipeline inspection apparatus for detection of longitudinal defects by flux leakage inspection of circumferential magnetic field
US3561256A (en) * 1969-03-28 1971-02-09 Exxon Research Engineering Co Pipeline leak detector
US3755908A (en) * 1971-01-13 1973-09-04 Williamson Inc T Pipeline pig
US3810384A (en) * 1971-02-01 1974-05-14 D Evans Ultrasonic pipeline inspection device
NL7214646A (fr) * 1972-10-30 1974-05-02
US3882606A (en) * 1973-05-16 1975-05-13 Amf Inc Method and apparatus for measuring curvature and curvature variations in pipelines and the like
US3903730A (en) * 1973-11-05 1975-09-09 Exxon Production Research Co Method of locating pipeline leaks with a one-way pig
GB1495754A (en) * 1974-05-08 1977-12-21 Underground Location Serv Ltd Measuring devices for bores and ducts
US4098126A (en) * 1976-04-06 1978-07-04 British Gas Corporation Non-destructive testing of pipeline
US4020674A (en) * 1976-05-19 1977-05-03 Harry Robert Fechter Pipeline leak detector with baffles
US4294869A (en) * 1979-09-26 1981-10-13 Martech International, Inc. Method for coating pipeline
US4457073A (en) * 1982-09-28 1984-07-03 T. D. Williamson, Inc. Pipeline pig having improved means of sensing changes in the internal configuration of a pipeline
GB8307985D0 (en) * 1983-03-23 1983-04-27 British Gas Corp Pipeline pig tracking
US4522063A (en) * 1983-09-16 1985-06-11 T. D. Williamson, Inc. Methods and apparatus for indicating selected physical parameters in a pipeline
US4641529A (en) * 1984-04-12 1987-02-10 Magnaflux Pipeline Services, Inc. Pipeline inspection device using ultrasonic apparatus for corrosion pit detection
US4541278A (en) * 1984-04-23 1985-09-17 Union Oil Company Of California Pipeline corrosion sensing device and method
US4953412A (en) * 1986-01-17 1990-09-04 T. D. Williamson, Inc. Pipeline caliper pig
US5088336A (en) * 1986-01-17 1992-02-18 Tdw Delaware, Inc. Pipeline caliper pig
US4747317A (en) * 1986-12-18 1988-05-31 Atlantic Richfield Company System for surveying fluid transmission pipelines and the like
US4930223A (en) * 1989-02-27 1990-06-05 Tdw Delaware, Inc. Bend detector pig
US5186757A (en) * 1991-08-26 1993-02-16 Abney Sr Marvin D Pig loading system and method thereof
US5532587A (en) * 1991-12-16 1996-07-02 Vetco Pipeline Services, Inc. Magnetic field analysis method and apparatus for determining stress characteristics in a pipeline
US5417112A (en) * 1993-01-11 1995-05-23 Tdw Delaware, Inc. Apparatus for indicating the passage of a pig moving within an underground pipeline
US5295279A (en) * 1993-01-13 1994-03-22 Tdw Delaware, Inc. Cup for use on a pipeline
US5549000A (en) * 1994-06-27 1996-08-27 Texaco, Inc. Passive acoustic detection of pipeline pigs
US5587534A (en) * 1994-10-28 1996-12-24 The United States Of America As Represented By The Secretary Of Commerce Wall thickness and flow detection apparatus and method for gas pipelines
US6679129B2 (en) * 1998-02-18 2004-01-20 Donsa, Inc. Pig for detecting an obstruction in a pipeline
US6857329B2 (en) * 1998-02-18 2005-02-22 Donsa, Inc. Pig for detecting an obstruction in a pipeline
GB9811474D0 (en) * 1998-05-29 1998-07-29 Tech 21 Limited Drogue leak detector for fluids in pipes
DE60034933T2 (de) * 1999-03-29 2008-01-24 Ftl Seals Technology Ltd., Morley Vorrichtung
US6895681B2 (en) * 2001-04-02 2005-05-24 Tokyo Gas Co., Ltd. Method and instrument for measuring inside diameter of conduit
AU2003261683A1 (en) * 2002-08-21 2004-03-11 Alexandr Efimovich Gurov Pipe, method and device for improved pipelines and similar objects
US7143659B2 (en) * 2002-12-17 2006-12-05 Pinnacle West Capital Corporation Pipe-inspection system
US7231812B1 (en) * 2005-10-27 2007-06-19 Lagare Michael E Conduit breach location detector
GB2462096A (en) * 2008-07-23 2010-01-27 Schlumberger Holdings Monitoring of a pipeline pig using external acoustic sensors
GB0815297D0 (en) * 2008-08-21 2008-09-24 Qinetiq Ltd Conduit monitoring
US8479345B2 (en) * 2009-08-12 2013-07-09 Tdw Delaware, Inc. Speed control drive section with failsafe valve
KR20110053499A (ko) * 2009-10-30 2011-05-24 김한식 송유관 내시경 장치 및 시스템
GB201110403D0 (en) * 2011-06-20 2011-08-03 Qinetiq Ltd Monitoring of conduits
ITMI20112239A1 (it) * 2011-12-12 2013-06-13 Eni Spa "pipeline inspection gauge per ispezione interna di condotte"
US8869599B2 (en) * 2012-01-23 2014-10-28 Massachusetts Institute Of Technology Leak detection system based on force transduction
ITMI20122196A1 (it) * 2012-12-20 2014-06-21 Eni Spa Metodo e sistema per la rilevazione da remoto della posizione di un dispositivo pig all'interno di una condotta in pressione
EA028210B1 (ru) * 2014-05-14 2017-10-31 Эни С.П.А. Способ и система для непрерывного дистанционного контроля положения и скорости продвижения скребкового устройства внутри трубопровода
CN104392592A (zh) * 2014-11-18 2015-03-04 中国石油天然气股份有限公司 一种清管器远程定位系统及方法
US9927060B2 (en) * 2015-04-22 2018-03-27 The Johns Hopkins University Vehicle for navigating within an enclosed space
CA2997209A1 (fr) * 2015-10-09 2017-04-13 Halliburton Energy Services, Inc. Evitement du danger pendant une reentree de puits
US11015996B2 (en) * 2016-07-26 2021-05-25 Halliburton Energy Services, Inc. Electro acoustic technology (EAT) for real time intelligent pigging
US10704935B2 (en) * 2016-12-04 2020-07-07 Buoy Labs, Inc. Fluid flow detector with tethered drag block
US11098836B2 (en) * 2017-09-19 2021-08-24 University Of Louisiana At Lafayette Device and method for detecting leaks and healing pipelines using twin balls technology
US11111468B2 (en) * 2018-04-10 2021-09-07 Lawrence Livermore National Laboratory, Llc Electromethanogenesis reactor
CN110045024A (zh) * 2019-05-30 2019-07-23 西南石油大学 一种输油管道缺陷超声探测装置

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20030185100A1 (en) * 2002-03-29 2003-10-02 Schlumberger Technology Corporation Assessing a solids deposit in an oilfield pipe
US20140331745A1 (en) * 2010-09-30 2014-11-13 Siemens Aktiengesellschaft Pipeline leak location using ultrasonic flowmeters
US20170254165A1 (en) * 2010-10-06 2017-09-07 Packers Plus Energy Services Inc. Actuation dart for wellbore operations, wellbore treatment apparatus and method
US20160199888A1 (en) * 2013-12-04 2016-07-14 Halliburton Energy Services, Inc. Deposit build-up monitoring, identification and removal optimization for conduits
WO2019199344A1 (fr) * 2018-04-12 2019-10-17 Halliburton Energy Services, Inc. Procédé et système de détermination non intrusive de variation transversale pour un canal fluidique

Also Published As

Publication number Publication date
US11519807B2 (en) 2022-12-06
MX2022005471A (es) 2022-06-02
BR112022007048A2 (pt) 2022-07-19
CA3145922A1 (fr) 2021-06-17
GB2604489B (en) 2023-10-04
AU2019477996A1 (en) 2022-02-24
CA3145922C (fr) 2023-08-15
GB2604489A (en) 2022-09-07
US20210180445A1 (en) 2021-06-17
NO20220540A1 (en) 2022-05-06

Similar Documents

Publication Publication Date Title
EP1889023B9 (fr) Deduction d'informations de fuites dans des tuyaux
US11455445B2 (en) Method and system for non-intrusively inspecting a fluidic channel
US9598642B2 (en) Distributive temperature monitoring using magnetostrictive probe technology
NO330549B1 (no) Fremgangsmate og anordning for a lokalisere en undergrunnskilde
US20160291186A1 (en) Seismic cable, system and method for acquiring information about seismic, microseismic and mechanical vibration incidents in a well
US10641735B2 (en) Remote-field eddy current based total thickness logging
EP3280875B1 (fr) Outil de surveillance d'écoulement
CA2890074C (fr) Diagraphie optique de puits
US9631474B2 (en) Systems and methods for real-time evaluation of coiled tubing matrix acidizing
US11448582B2 (en) Method and system for non-intrusively determining properties of deposit in a fluidic channel
NO316294B1 (no) Fremgangsmåte og anordning for reservoarovervåkning via en klargjort brönn
CA3145922C (fr) Procede et systeme de determination de variations dans un canal fluidique
US11513247B2 (en) Data acquisition systems
NL2022689B1 (en) Method and system for non-intrusively determining cross-sectional variation for a fluidic channel
US20150000979A1 (en) System and method for detecting underground cross-bores
US20210277771A1 (en) Distributed acoustic sensing for coiled tubing characteristics

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 19955482

Country of ref document: EP

Kind code of ref document: A1

ENP Entry into the national phase

Ref document number: 3145922

Country of ref document: CA

ENP Entry into the national phase

Ref document number: 2019477996

Country of ref document: AU

Date of ref document: 20191213

Kind code of ref document: A

REG Reference to national code

Ref country code: BR

Ref legal event code: B01A

Ref document number: 112022007048

Country of ref document: BR

ENP Entry into the national phase

Ref document number: 202206614

Country of ref document: GB

Kind code of ref document: A

Free format text: PCT FILING DATE = 20191213

NENP Non-entry into the national phase

Ref country code: DE

ENP Entry into the national phase

Ref document number: 112022007048

Country of ref document: BR

Kind code of ref document: A2

Effective date: 20220412

122 Ep: pct application non-entry in european phase

Ref document number: 19955482

Country of ref document: EP

Kind code of ref document: A1